Subterranean drilling operations are often performed to locate (exploration) or to retrieve (production) subterranean hydrocarbon deposits. Most of these operations include an offshore or land-based drilling rig to drive a plurality of interconnected drill pipes known as a drillstring. Large motors at the surface of the drilling rig apply torque and rotation to the drillstring, and the weight of the drillstring components provides downward axial force. At the distal end of the drillstring, a collection of drilling equipment known to one of ordinary skill in the art as a bottom hole assembly (“BHA”) is mounted. Typically, the BHA may include drill bits, drill collars, stabilizers, reamers, mud motors, rotary steering tools, measurement-while-drilling sensors, and any other devices useful in subterranean drilling.
While most drilling operations begin vertically, boreholes do not always maintain that vertical trajectory along their entire depth. Frequently, changes in the subterranean formation may direct the borehole to deviate from vertical, as the drillstring has a natural tendency to follow a path of least resistance. For example, if a pocket of softer, easier to drill, formation is encountered, the BHA and attached drillstring may deflect and proceed into that softer formation more easily that a relatively harder formation. While relatively inflexible at short lengths, drillstring and BHA components become somewhat flexible over longer lengths. As borehole trajectory deviation is typically reported as the amount of change in angle (i.e. the “build angle”) per one hundred feet drilled, borehole deviation may be imperceptible to the naked eye. However, over distances of over several thousand feet, borehole deviation may be significant.
Furthermore, it should be understood that many borehole trajectories today desirably include planned borehole deviations. For example, in formations where the production zone includes a horizontal seam, drilling a single deviated bore horizontally through that seam may offer more effective production than several vertical bores. Furthermore, in some circumstances, it is preferable to drill a single vertical main bore and have several horizontal bores branch off therefrom to fully reach and develop all the hydrocarbon deposits of the formation. Therefore, considerable time and resources have been dedicated to develop and optimize directional drilling capabilities.
Typical directional drilling schemes include various mechanisms and apparatuses in the BHA to selectively divert the drillstring from its original trajectory. One such scheme includes the use of a mud motor in combination with a bent housing device to the bottom hole assembly. In standard rotary drilling practice, the drillstring is rotated from the surface to apply torque to the drill bit below. On the other hand, using a mud motor attached to the bottom hole assembly, torque may be applied to the drill bit therefrom, thereby eliminating the need to rotate the drillstring from the surface. While many varieties of mud motors exist, most may either be classified as turbine mud motors (i.e., turbodrills) or positive displacement mud motors. Regardless of design specifics, most mud motors function by converting the flow of high-pressure drilling mud into mechanical energy.
Drilling mud, as used in oilfield applications, is typically pumped to a drill bit downhole through a bore of the drillstring at high pressure. Once at the bit, the drilling mud is communicated to the well bore through a plurality of nozzles where the flow of the drilling mud cools, lubricates, and cleans drill cuttings away from cutting surfaces of the drill bit. Once expelled, the drilling mud is allowed to return to the surface through an annulus formed between the wellbore (i.e., the inner diameter of either the formation or a casing string) and the outer profile of the drillstring. The drilling mud returns to the surface carrying drill cuttings with it.
When a mud motor is used, it is not necessary to rotate the drillstring to rotate the drill bit with respect to the borehole. Instead, the drillstring located above the mud motor is allowed to “slide” into the wellbore as the bit penetrates the formation. As mentioned above, a bent housing may be used in conjunction with a mud motor to directionally drill a well bore. A bent housing may be similar to an ordinary section of the BHA, with the exception that a low angle bend is incorporated therein. Further, the bent housing may be a separate component attached above the mud motor (i.e. a bent sub), or may be a portion of the motor housing itself.
Through various measurement and telemetry devices in the BHA, a drilling operator at the surface is able to determine which direction the bend in the bent housing is oriented. The drilling operator may then rotate the drillstring until the bend is in the direction of a desired deviated trajectory and the drillstring rotation is stopped. The drilling operator then activates the mud motor and the deviated borehole is drilled, with the drillstring advancing without rotation into the borehole (i.e. sliding) behind the BHA, using only the mud motor to drive the drill bit.
When the direction change is complete and a “straight” trajectory is again desired, the drilling operator rotates the entire drillstring continuously to eliminate the directional effect the bent housing has on the drillstring trajectory. When a change of trajectory is again desired, drillstring rotation is stopped, the BHA is again oriented in the desired direction, and the mud motor drills in that trajectory while the remainder of the drillstring slides into the wellbore.
One drawback of directional drilling with a mud motor and a bent housing arises when the drillstring rotation is stopped and forward progress of the BHA continues with the mud motor. During these periods, the drillstring slides further into the borehole as it is drilled and does not enjoy the benefit of rotation to prevent it from sticking in the formation. Particularly, such operations may carry an increased risk that the drillstring will become stuck in the borehole and will require a costly fishing operation to retrieve the drillstring and BHA.
More recently, in an effort to combat issues associated with drilling without rotation, rotary steerable systems (“RSS”) have been developed. In a rotary steerable system, the BHA trajectory is deflected while the drillstring continues to rotate. As such, rotary steerable systems are generally divided into two types, push-the-bit systems and point-the-bit systems. In a push-the-bit RSS, a group of expandable thrust pads extends laterally from the BHA to thrust and bias the drillstring into a desired trajectory.
An example of one such system is described in U.S. Pat. No. 5,168,941. In order for this to occur while the drillstring is rotated, the expandable thrusters extend from what is known as a geostationary portion of the drilling assembly. Geostationary components do not rotate relative to the formation while the remainder of the drillstring is rotated. While the geostationary portion remains in a substantially consistent orientation, the operator at the surface may direct the remainder of the BHA into a desired trajectory relative to the position of the geostationary portion with the expandable thrusters.
In contrast, a point-the-bit RSS includes an articulated orientation unit within the assembly to “point” the remainder of the BHA into a desired trajectory. Examples of such a system are described in U.S. Pat. Nos. 6,092,610 and 5,875,859. As with a push-the-bit RSS, the orientation unit of the point-the-bit system is either located on a geostationary collar or has a mechanical or electronic geostationary reference plane, so that the drilling operator knows which direction the BHA trajectory will follow. Instead of a group of laterally extendable thrusters, a point-the-bit RSS typically includes hydraulic or mechanical actuators to direct the articulated orientation unit into the desired trajectory.
As such, a mud motor may be used in conjunction with a RSS directional drilling system. Particularly, in certain circumstances, the bit may drill faster when the RSS and bit are driven by the mud motor, which results in a greater rotation speed than can be provided by the drill string alone. In such an arrangement, a drillstring may be rotated at a relatively low speed to prevent drillstring sticking in the wellbore while a mud motor output shaft (i.e., a rotor) positioned above an RSS assembly drives the drill bit at a higher speed.
As such, a positive displacement mud motor (“PDM”) converts the energy of high-pressure drilling fluid into rotational mechanical energy at the drill bit using the Moineau principle, an early example of which is given in U.S. Pat. No. 4,187,918. A PDM typically uses a helical stator attached to a distal end of the drillstring with a corresponding eccentric helical rotor engaged therein and connected through a driveshaft to the remainder of the BHA therebelow. As such, pressurized drilling fluids flowing through the bore of the drillstring engage the stator and rotor, thus creating a resultant torque on the rotor which is then transmitted to the drill bit below. Historically, positive displacement mud motors have been characterized as having a low-speed, but high-torque output to the drill bit. As such, PDM's are generally best suited to be used with roller cone and polycrystalline diamond compact (PDC) bits. Further, because of the eccentric motion of their rotors, PDM's are known to produce large lateral vibrations which may damage other drill string components.
In contrast, turbine mud motors use one or more turbine power sections to provide rotational force to a drill bit. Each power section consists of a non-moving stator vanes, and a rotor assembly comprising rotating vanes mechanically linked to a rotor shaft. Preferably, the power sections are designed such that the vanes of the stator stages direct the flow of drilling mud into corresponding rotor blades to provide rotation. The rotor shaft, which may be a single piece, or may comprise two or more connected shafts such as a flexible shaft and an output shaft, ultimately connects to and drives the bit. Thus, the high-speed drilling mud flowing into the rotor vanes causes the rotor and the drill bit to rotate with respect to the stator housing. Historically, turbine mud motors have been characterized as having a high-speed, but low-torque output to the drill bit. Furthermore, because of the high speed, and because by design no component of the rotor moves in an eccentric path, the output of a turbine mud motor is typically smoother and considered appropriate for diamond cutter bits. Generally, the “stator” portion of the motor assembly is the portion of the motor body that is attached to, and rotates at the same speed, as the remainder of the drillstring and the BHA.
However, because turbine mud motors are characterized by low torque output, drill bits attached thereto are more susceptible to becoming stuck when encountering certain formations. This occurs when the torque needed to rotate the bit becomes greater than the torque which the motor vanes are able to generate. In the event a drill bit becomes stuck during “rotary” drilling (i.e., drilling in which only drill string rotation is used to drive the bit), it is a common practice to apply a large torque at the surface through the entire drillstring to free the drill bit. However in BHAs in which downhole motors are used, the rotation between the rotor and stator may prevent the transmission of torque from the drillstring to the drill bit. As a result, the only torque that may be transmitted to a stuck drill bit to free the bit is the torque that the mud motor is able to produce. Because turbine mud motors generate relatively low torque, they may not be able to dislodge a stuck drill bit.
There have been several attempts to create means to lock the motor or turbine housing to the rotor shaft in the event that the bit becomes stuck, including those shown in U.S. Pat. Nos. 2,167,019, 4,232,751, 4,253,532, 4,276,944, 4,299,296, and 4,632,193. These devices generally required intervention from the surface, such as pulling or pushing on the drill string, or manipulating fluid flow rate, to engage a clutch device.
Other references disclose “one-way clutch” devices which have means to automatically lock the rotor to the stator when the body is rotating and the bit is stalled, and allow the rotor to rotate freely when the bit speed is greater than the stator speed. These devices, however, do not have provision to prevent the locking means from rubbing on the mating rotor or stator during normal operation (i.e. when the bit is not stuck, and the shaft is rotating at a faster speed than the motor body). As such, the locking means are likely to abrade rapidly and lose their function, unless they are in a sealed environment and thereby protected from abrasion by the drilling mud. However, at the relatively high speeds of turbines and some high-speed mud motors, seals are notoriously unreliable, so most downhole turbines and mud motors are constructed with non-sealed, mud-lubricated bearing assemblies.
What is still needed are downhole motors and methods for preventing a drill bit from becoming stuck and for freeing a stuck drill bit. It is desirable to be able to apply torque from the drillstring to the stator of a downhole motor and then from the stator of the motor to a rotor, without requiring manipulation of the drill string or the flow rate. Further, it is beneficial to provide means to engage the motor stator to the motor rotor when the bit is stuck and the stator is free to rotate, and to disengage those means when the rotor is rotating at some rotational speed which is greater than the rotational speed of the stator.